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spk01: Good day ladies and gentlemen and welcome to the Continental Resources, Inc. second quarter 2021 earnings conference call. At this time all participants are in a listen only mode. Later we will conduct a question and answer session and instructions will follow at that time. Should you need assistance please signal a conference specialist by pressing the star key followed by zero. As a reminder this conference call is being recorded. I would now like to turn the conference call over to Rory Sabino, Vice President of Investor Relations. Please go ahead.
spk07: Great. Good morning, and thank you for joining us. Welcome to today's earnings call. We will start today's call with remarks from Bill Berry, Continental's Chief Executive Officer, and Jack Stark, President and Chief Operating Officer. Bill and Jack will be joined by additional members of our team, including Mr. Harold Hamm, Chairman of the Board, John Hart, Chief Financial Officer and Chief Strategy Officer, and other members of our team. Today's call will contain forward-looking statements that address projections, assumptions, and guidance. Actual results may differ materially from those contained in forward-looking statements. Please refer to the company's SEC filings for additional information concerning these statements and risks. Continental does not undertake any obligation to update forward-looking statements made on this call. Finally, on the call, we will refer to certain non-GAAP financial measures. For a reconciliation of these measures to generally accepted accounting principles, please refer to the updated investor presentation that has been posted on the company's website at www.clr.com. With that, I will turn the call over to Mr. Berry. Bill?
spk11: Thank you, Rory, and good morning, everyone. Thank you for taking time to join us on our call. I hope everyone is well. I'd like to begin by highlighting our exceptional performance in the second quarter where we generated robust and company record-breaking free cash flow thanks to strong asset performance in addition to continued capital and operating efficiency gains delivered by our teams. This significant free cash flow is being dedicated to shareholder capital returns in the form of an increased quarterly dividend to 15 cents per share, continued focus on debt reduction and resumption of our $1 billion share repurchase program. We appreciate our investors' support and hope this continues to provide confidence in Continental being the best investment opportunity in the industry and the most shareholder return-focused company in any industry. During the second quarter, we generated a company record-breaking $634 million of free cash flow. reduced net debt by $284 million, ending the quarter with $4.59 billion. Year-to-date, we've generated $1.24 billion in free cash flow while reducing our net debt by $892 million. We distributed $40 million to shareholders with our previous 11-cent quarterly dividend, exceeded our production guidance for the quarter, delivering 167,000 BOE a day, and just over barrels of oil a day and just over 1 billion cubic feet of gas per day. We delivered exceptional performance and efficiencies from our assets in the Bakken and Oklahoma, which Jack will provide more details. With respect to hedging, we remain unhedged on crude oil. On gas, we have about approximately 50% of our volume hedged through year-end with a combination of swaps and collars that provide a floor around three, while we're retaining price upsides of over $5. For 2022, we have no gas hedges beyond the first quarter and no oil hedges at all in 2022. While we remain bullish on commodity prices given the volatility of price cycles and potential impact of and government reaction to COVID variants, we continue to believe it is inappropriate for the industry to overproduce into a potentially oversupplied market, particularly with respect to crude oil. As I highlighted last quarter, we remain focused on our strategic vision with four key elements I'd like to briefly discuss today. Free cash flow commitment, capital discipline, strengthening the balance sheet, and corporate and cash returns to shareholders. Let me start with our commitment to free cash flow and capital discipline. Our cash flow generation is robust and competitively advantaged versus our peers, given our unhedged crude oil profile as shown in slide four. In the first half of the year, we have, year to date, already generated the free cash flow we were projecting for the entirety of 2021. We are now seeing the potential to generate approximately $2.4 billion of free cash flow at current strip prices this year, which equates to an approximately 19% free cash flow yield. Given our disciplined response to rising commodity prices, our CapEx budget for 2021 has not changed, and our reinvestment rate is trending toward 35%. With regard to strengthening the balance sheet, our net debt reduction is tracking toward $1.8 billion in 2021, which will bring our year-end net debt close to $3.7 billion. We expect to meet or exceed our leveraged target of one-time net debt to EBITDA this year, but are not finished there. Our intention is to reduce absolute debt to one-time at $50 to $55 WTI, which equates to approximately $3 billion in debt. Alongside our strong inventory and commodity optionality, we are confident our net debt outlook is one of the many powerful attributes for both the company and our shareholders. And we believe our current credit metrics are reflective of investment grade. So let me now discuss corporate returns and cash returns to investors. We're generating strong Corporate returns are projecting to deliver 18 percent return on capital employed in 2021. Additionally, we are committed to disciplined and significant shareholder returns through net debt reduction and prioritizing cash returns using the multiple vehicles we have to return cash to investors, including our dividend and share repurchases. We are committed to growing our dividend in a competitive and sustainable manner. That is why we increased our quarterly fixed dividend by 36 percent versus last quarter. to 15 cents a share. This is triple our original dividend rate and equals to an approximately 1.7 annualized dividend yield, which we believe is competitive with industry peers and shows ongoing growth in cash returns. We are resuming our share repurchase program of $1 billion, which began in 2019 with $317 million of purchases previously executed, $683 million of capacity remains. Given our significant shareholder alignment, you can be confident that shareholder capital returns will remain a significant priority for our company. The combined shareholder capital returns in the form of the annualized dividend and projected net debt reduction by year in 2021 alone would equate to 53% of the company's projected full year 2021 cash flow from operations and 16% of the current company's current capital market. Share repurchases would be additive to these figures, depending on the timing of additional share repurchases, which we expect to be in the near future. 2021 guidance updates. Let me share with you a little bit of where we are on that. As we look ahead to the remainder of 2021, several of our key metrics are materially outperforming our original guidance, such that we have updated for the following. Natural gas production in 2021 is now expected to range between 900 million and one BCF a day. Production expense is projected to be $3 to $3.50 per BOA, better than the original guidance of $3.25 to $3.75. Additionally, as reflected on slide 16, we have improved our guidance on DDNA and crude and gas differentials. I also want to highlight our continued focus on ESG. We recently released our 2020 ESG updates, which can be found on our website, www.cit.clr.com. ESG has always been a key part of our DNA and something we have highlighted as a means to steward our company. While there is a lot of focus on the environmental, or E, from all of us, we believe the S, societal, is underrepresented in the global dialogue. A lack of energy access across the world equates to poverty, which all members of society should seek to improve. Our ESG efforts remain focused on continuously improving, and our approach is to look at all operational impacts, including land, water, and air. We believe it is essential all countries and all economic participants do their part to improve ESG in the same way in order to better our world. Crude oil and natural gas will continue to play a vital role in the global energy mix, and the entire world needs multiple forms of energy to move people from poverty to appropriate levels of societal quality of life. In closing, I did want to provide an update on the launch of the new futures contract, Midland WTI American Gulf Coast, which will start trading on the Intercontinental Exchange by year end. This is a culmination of recommendations by the AGS Best Practices Task Force, led by Harold Hamm, along with efforts by Magellan and Enterprise Products, and will be an exciting opportunity for U.S. producers seeking greater transparency, more liquidity, and access to global markets. I'll now turn the call over to Jack to discuss our operational performance.
spk10: Thanks, Bill, and good morning, everyone. Appreciate you joining our call. Today I'm going to share some highlights from the outstanding results our teams delivered this quarter, and there are three key takeaways I want to leave you with. First, our assets are performing with remarkable consistency and predictability, delivering returns in excess of 100% from our Bakken and 60 to 80% for our Oklahoma drilling programs, assuming $60 WTI and $3 NIMAC gas. Second, we are on track to reduce our weighted average cost per well year over year by approximately 10% and 70 to 80% of these savings are structural. Third, our capital efficiencies are reaching record levels and we expect to deliver a projected return on capital employed of approximately 18% for 2021. Our assets also provide optionality to respond to changing market conditions. For example, the decision to focus up to 70 percent of our rigs on our Oklahoma natural gas assets in the second quarter last year has proven to be very strategic. Our second quarter 2021 natural gas production in Oklahoma was up approximately 10 percent over the first quarter of 2020, while NYMEX natural gas prices more than doubled over this same period of time. With today's improved crude prices, we are exercising this optionality once again, and migrating up to 75% of our rigs to a more oil-weighted portfolio in the back half of this year. As Bill highlighted, our oil production remains unhedged, and our shareholders are receiving the full benefit of the improved crude oil price. So let's get into the quarterly highlights. During the quarter, we brought on 108 gross-operated wells with 70 in the Bakken and 38 in Oklahoma. Early performance from our 2021 Bakken wells is right on track, as shown on slide 8. This chart compares the average performance of our 2021 wells with average performance of 488 continental operated wells completed over the prior four years, grouped by program year. The overlap of these annual performance curves illustrates the consistent performance the Bakken has delivered year over year, which is arguably the best repeatability of any oil play in the country. Over the last four years, we have also reduced our cycle time for putting Bakken wells online by 50%, and dropped our completed well cost by approximately 30%, driving our capital efficiencies in the Bakken to record levels. Today, we are producing approximately 45% more BOE per $1,000 spent in the first 12 months than we did in 2018. Our Bakken differentials are also improving, driven by demand for Bakken crude and the expansion of DAPL, which was put into operation August 1st. With this expansion, there's approximately 1.6 million barrels of pipeline and local refining takeaway capacity from the Bakken, excluding rail. This is approximately 500,000 barrels per day more than the Bakken field produced on average in the month of May. Bottom line, considering all of these improvements and the bullish market fundamentals, we are potentially entering one of the most profitable chapters in the history of the Bakken, Continental and its shareholders. Before leaving the Bakken, I should point out that 11 of our second quarter Bakken completions we're located in our Long Creek unit. These 11 wells are excellent producers, as shown on slide nine. Equally impressive are the well costs that are coming in below original estimates at approximately 6.1 million per well. Recent results are bellwether for things to come as we continue developing a total of 56 wells in this unit, and we expect to complete about 30% of these wells by year end 2021, 50% in 2020, and the remaining 20% in early 2023. In Oklahoma, we continue to see excellent results from really both our oil and gas condensate wells as illustrated on slide 10. These charts show the average well performance by year in all four of our springboard project areas over the last two and a half years. In springboard one and two, you can see that the average well performance has improved over time with great repeatability in both the condensate and oil windows. This includes 155 operated wells, of which 70 percent were oil and 30 percent were condensate wells. Now, the chart on the lower left of slide 10 shows impressive performance from our operated oil wells in springboard three and four. This is a small data set, so we chose to break the average annual performance by producing formation to provide more color on the results we have seen to date. The chart includes seven Woodford and four Sycamore wells that we completed over the last two and a half years. The key observations from this chart is that the seven Woodford wells are performing in line with springboard one and two oil wells, while the four Sycamore wells that were completed in 2019 are significantly outperforming. Even more impressive is that we're on track to reduce our completed well costs by approximately 17% year over year. Since 2018, our teams have reduced completed well costs in Oklahoma by a total of 40%, which, as in the Bakken, has driven our capital efficiencies to record levels in Oklahoma. As shown on slide 11, we are producing approximately 80% more BOE per $1,000 spent in the first 12 months than we did in 2018. Approximately 70% of these savings are sustainable driven again by technology and updated designs that increase performance and reduce cycle times. In the Powder River Basin, our drilling is proceeding right on schedule. Our drilling teams are doing a great job and have met and exceeded our early expectation for drilling days and costs. We have six wells waiting on completion and expect to have some results to share later this year. We currently have two rigs drilling through year end. Looking ahead, we are maintaining our oil production guidance for the year. I should point out that our second quarter production was boosted by accelerating the completion of select third quarter wells and putting them online in the second quarter. In the fourth quarter, we are projecting a December exit rate of approximately 165,000 barrels of oil per day. We currently have eight rigs drilling in Ibakan, two in the Powder, and five in Oklahoma, and are considering adding up to one rig in the Bakken and two in Oklahoma by year end. In closing, I'll mention that our exploration teams at Continental continue to generate new opportunities within and outside of our core operating areas. Later this year, we plan to do some exploratory drilling to test a couple of these new opportunities. Details must remain confidential, but I can tell you that with success, each of these opportunities could add significantly to our deep inventory. So with that, we are now ready to begin the Q&A section of our call, and I will turn the call over to the operator.
spk01: We will now begin the question and answer session. To ask a question, you may press star, then 1 on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star, then 2. Please limit yourself to one question and one follow-up. At this time we will pause momentarily to assemble our roster. And our first question will come from Arun Jayaram of JP Morgan. Please go ahead.
spk05: Yeah, good morning, good afternoon. I wanted to get management's view on just how you're thinking about, you know, incremental, cash return. Obviously, you increased the dividend, but I wanted to get your perspective on why you went with buybacks versus variable dividends. I'd love to hear what kind of feedback you're getting from investors regarding cash return, including Harold's view, given his ownership position in the company.
spk11: Well, thanks, Haroon. I know that's the question of the moment, and everyone's keenly focused on that. We've done a lot of a lot of work internally with our discussions, not only with the board, but also with analysts such as yourself, as well as our investors, and just say, what's the preferred vehicle? And we've seen a lot of comments that there's a very high level of comfort that the share buyback is the actually preferred vehicle. I know a lot of companies are actually engaging in some special dividends, some variable dividends, and I think all of us are watching to see how that actually gets played out in the market. Today, we're seeing a preference for buyback, and Harold's here with us, and he can probably share with you his perspective on that as well.
spk13: Harold Phillips Yeah, Aaron, that's a good question. All across the sector, I think we realize the undervalued market that we're in today, We feel like the buybacks are a good thing to do at this particular time.
spk05: Fair enough.
spk11: And, Aaron, just to follow up on that, one of the things that you'll look to on slide five is look at what our cash flow yield is. That suggests that we're significantly undervalued, and so I think the buyback is the appropriate vehicle to use in that type of scenario.
spk05: Great, great. And then just my follow-up, it sounds like late in the year you may add a rig in the Bakken, a couple in Oklahoma if I heard you correctly. So how are you guys thinking about, you know, 2022? I know you have a targeted reinvestment rate range that you've put out there, but how are you thinking about, you know, preparing for 2022 if we get some of those OPEC Plus barrels back online?
spk11: Yeah, let me start, and then Jack may add some color to it on the rigs. But we're very comfortable with what we've articulated before, that 65% to 75% reinvestment ratio is about the right level. We're obviously well below that today. We're 35%. But the things that we've talked about for the last several quarters is there is still a pretty significant production overhang that's out there. If you look at OPEC+, it's probably 5 million barrels a day. the COVID variant delta, and we're all seeing what's happening to that here in our country, but also around the world. You see particularly what's happening in Asia on this, so the demand side. So both those things are out there that suggest that as we look forward into the future, our reinvestment ratio still seems to be the right thing for us to be focusing on. As far as additional I think the way Jack articulated was the possibility of doing that. We're still looking at it. And, Jack, I don't know if you've got any other texture on the rigs we're picking up toward the end of the year.
spk10: No, clearly we have the inventory to move into it. As you said, we're keeping our eye on the macro, and we'll adjust accordingly. Great. Thanks a lot, gents. Thanks, Eric.
spk01: The next question comes from Doug Legate of Bank of America. Please go ahead.
spk02: Thank you. Good morning, everyone. I hope everyone's doing well out there. I appreciate you getting on the call this morning. So, gentlemen, first of all, the fact that you've deliberately run an unhedged business is clearly paying dividends, as is your capital allocation strategy. But I want to put a scenario to you and ask your opinion on this. The market is pricing the sector, in our opinion, at the strip price, which is $20 backwardated over a four or five year period. And it seems to us that the free cash flow you're generating as a proportion of your free float is extraordinary, frankly, given you've only got a 15% free float. So my question is, how far can you take the buyback? Because it seems the scale of free cash flow in the next two or three years could be very significant compared to what the market is pricing you at based on the strip.
spk11: Yeah, Doug, it's a great question. And we see it exactly the same way that the pricing at the strip is $20 backward dated. That does, and I think that's what you're describing with your question here. It does suggest that a buyback is an appropriate vehicle. Going forward into 2022, I'll probably revisit those same comments made earlier that there is a risk overhang with that production capacity and with the demand side of things with with COVID that's out there. So it's probably pretty early to be articulating where we end up going in the future in the 22, 23 timeframe, which I think is the root of your question. Absolutely the right question. We talk about it every day, but as far as guidance, it's probably not now that we feel it's the right time to be making that guidance in the future. But with regard to the macro, I might see if Harold's got any thoughts he wants to share with you as well. Thanks, Doug.
spk13: I think you're right on, Phil. We're seeing this overhang diminish actually week by week and month by month. Until that's gone, I don't think anybody can say exactly what the future holds.
spk02: You see my point, though, fellas. You're buying back essentially about 40% of your free float. That's going to be tough to sustain at that rate without the inevitable happening, which is the free float doesn't stick around for too much longer. I just wonder if I'm thinking about that the right way.
spk13: Well, obviously, we hope we don't have to continue doing that. We hope that over the next few quarters, we'll see things change.
spk11: Yeah, Doug, we hope that people see it the same way you do and start buying the stock, and then that drives it to the position that we don't think we're needing to buy it.
spk02: Okay, well, my follow-up, hopefully, is a bit quicker than that. And it's really just about capital allocation. You took advantage of, you know, the weakness in oil prices. You pivoted to your gas optionality. What are you doing today? Because, obviously, both sides of the coin are pretty good. How are you allocating capital today? And I'll leave it there. Thanks.
spk11: Yeah, no, it's a great question, Doug. And we have lots of discussions internally about that very subject. It's great to have the optionality. And I think that's what you're seeing with some of Jack's comments. And I'll have him talk to you a little bit about what we're doing on the, you know, where we're headed in the latter part of the year on the oil versus gas. But both of the commodities are seeing some good strength and we're seeing the capability to go easily.
spk10: Yeah. I mean, that's the beauty of it is, and you're exactly right. We've talked about this a lot. Do we continue on with gas prices where they're at and be a little more aggressive on the gas? Or do we, you know, push to a more oil-weighted portfolio and And right now, I mean, we're looking at, as we said, adding another rig in the Bakken. And we do, just from where we're at right now as a percentage of rigs, we're seeing that we will become more oil-weighted in the back half of the year here. Just by allocation of rigs, we probably have, as I said, could be upwards of 75% of the rigs more focused on oil. And when you look at the completions in the back half of the year, you've got close to 70% of them are really going to be in the Bakken. So you will see, obviously, that tick up. But believe me, the guys in Oklahoma with just some outstanding wells, I mean, we've had some wells we've put on here recently. I mean, I think it's going to be somewhere in the range of, Doug, I wish I knew the number, but it's going to be somewhere in the range of like eight wells we brought on here that are in the gas window. And there are 13, 15 million a day with like 300, 350 barrels of condensate with them. And so just outstanding well. So we have the option to go either way. You're exactly right. We're looking at $4 gas, pretty darn attractive time to bring on gas as well. So we're just kind of, we feel like we're a little bit in the catbird seat and we can take advantage and adjust rigs as we think, where we think we can get the best benefit.
spk02: Jack, I might have to republish our stock primer when Rory was over here. But anyway, congrats on a great quarter, guys. Thank you. Thanks, Doug. Thanks, Doug.
spk01: The next question comes from Derek Whitfield of CIFL. Please go ahead.
spk03: Good morning, all. Congrats on your strong quarter and return of capital program or return of capital update.
spk11: Thanks, Derek.
spk03: With the understanding that you're firmly signaling a strong commitment to capital discipline, could you outline the macro conditions that would signal the need for return to growth and how measured Continental's response would be in a more naturally balanced supply-demand environment?
spk11: Yeah, I think the thing that we always look at there is the fundamentals, and that's what we've talked about for quite some time. It's a supply-demand balance, and We continue to look at that as we talked about the supply side of things. You know, it's got a little bit of production overhang. The demand side, you know, still got that risk. So to look at whether those come back together to a reasonable period of time. And then to the earlier conversation, I think what we were talking about on the reinvestment rate, the 65% to 75%, that's kind of where we think is an appropriate level for us to be on a long-term basis. And again, what we... are focused on mid-cycle type numbers, and so you'll see that in the conversations. Even when we look at what's our debt to EBITDA and where we are today, we're really looking at longer term what's the right debt to EBITDA. It drops us down to $3 billion or less on a debt basis, and that's kind of the driver for our overall cash distribution. The one other thing that we'll highlight to you is that we've got a six-year track record of free cash flow return, and that's what we always focus on. It's a very aligned management and ownership team to continue to deliver free cash flow, strong free cash flow to our investors.
spk03: Great. That makes sense. With my follow-up, I wanted to focus on your strong results in the springboard three and four areas as shown on slide four. How would you compare the economics of springboard three and four to that of other areas across the Anadarko And how should we think about the allocation of activity to the Anadarko as you increase your focus on oil in the second half and potentially out to 2022?
spk10: Well, good question here. And the purpose of this slide is to show that the returns and the performance that we're seeing here are very similar in these areas. And I agree with you. You're looking at this and you're going, With this kind of performance, where does springboard say three and four fit into the equation? We're just in our very early stages of developing springboard three and four. We're not even 5% into the inventory there, but what we wanted to show on this slide is that the early performance from the wells in the Woodford and the Sycamore here are really they're right in line with the much higher statistical average we have, you know, from our oil wells in springboard one and two. And, you know, to see this kind of results early in a play is extremely encouraging. But, you know, it's partly because it's in our area and we know what we're doing here. And so what does this portray for other areas? I think what you have to understand is we've got 360 square miles of reservoirs with stack pays upwards of about 300 to 750 foot thick in here. And we really control these areas. Our average work interest is 75%. So as to the whole Anadarko Basin, I can't speak to that, but as far as to Continental, we have basically control of what I'd call the best portion of the reservoirs out here. And that's because we're an early entrant into the play. You know, we were leasing out here in 2008 when nobody really cared. It was a really tough time in the market. And so, you know, our positions are so dominant just because of that. And we stayed focused on it through, you know, and we've done some strategic bolt-ons to continue to build our positions. And so right now we have upwards of 600 gross-operated locations remaining. And so a lot to do out here. And what's really encouraging on this is that, you know, a lot of the drilling has been Woodford and Springer with some Sycamore out here. Well, now you look at the Sycamore performance down here in Springboard 3 and 4, and it's pretty darn impressive in performance there. And Sycamore represents about a third of the inventory that I'm talking about here. So in the end, I think you take away from this one slide here in the deck, is that springboard one and two are not one-offs. They're actually, we're continuing with three and four, and we actually have some other areas out here that, you know, that will be springboard five and six, ultimately, we believe. And so the point of it is that good, consistent results, and that's what we'd love to see, but it's because we know the rocks and how to develop them. That's great.
spk03: Thanks, Ricky.
spk10: Long-winded answer. I'm sorry, but I just – I guess I get off my soapbox.
spk03: You can tell we're excited about the area. Yeah, greatly appreciate it about the detail. I mean, the results look fantastic, so I wish you guys the best of luck out here in the future wells. Thank you. Thank you.
spk01: The next question comes from Neil Dingman of Truist Securities. Please go ahead.
spk04: Mornell, Jack, just maybe a little more on your sub box on the mid-con. Can you talk, what's the latest and does the sub-site include some of the potential around the Franco-Nevada JV and maybe any comments you could have around that and the opportunities that's provided?
spk10: Well, regarding the Franco-Nevada JV, I mean, it basically has representation through all these areas, bottom line. As far as that's concerned, it definitely has exposure to these performance results that you're seeing here and will continue for quite some time. And what was the other part of your question?
spk04: Well, I'm just wondering, you know, with that, Frank, is there going to be a potential to, I don't know, down the road, would you potentially spin that off? Would you do something with that? Or, you know, is it just, you know, with what it's helping with returns, there's no near-term plans with that JV?
spk12: It's another area of optionality we've got. It's a tremendous asset for the future. We're growing that asset today. Today is not the day to delve into that, but we do see a lot of optionality in the future. We're obviously in it to grow value and to do something that's valuable to our shareholders.
spk04: Makes sense, John. And then one follow-up, if I could, just you guys have been great. on seeing some marketing opportunities. I'm just wondering, either for you or even Harold, how you see for export opportunities and what are the market opportunities you all see here in the coming quarters?
spk13: I think over the coming few quarters, we're seeing the export market has stayed strong. Obviously, a lot of us go on to Southeast Asia and We expect that to remain strong in the future. We're seeing also, you know, Brent and WTI prices continue to close. So that's positive. You know, maybe that's somehow in anticipation of a new market that's been created in the Gulf.
spk04: Great point. Thanks, Harold.
spk13: Yes.
spk01: The next question comes from Leo Mariani of KeyBank. Please go ahead.
spk06: Hey, guys. I wanted to follow up on one of your prepared comments from earlier. I just wanted to make sure that I heard this right. I think you guys talked about kind of a year-end 21 exit rate around 165,000 BUE per day on oil this year. I noticed that you guys were at about 167,000 in the second quarter. I guess I thought that you guys were kind of ramping up oil-weighted activity in the second half. So I guess I would have maybe expected your oil volumes to continue to kind of march higher in the second half. So maybe can you just help me kind of reconcile all that in my mind? I just want to make sure I'm kind of understanding the plan here.
spk10: Yeah, sure, Leo. I understand that, your thought there. Really, yeah, we were talking about a December exit rate at 165, around that. When you look at it, because we moved wells from the second quarter or from the third quarter into the second quarter – we're seeing about 60% of the wells for the year actually have been completed in the first half of the year, and so we have about 40% of the wells to be completed here in the second half of the year. So that's a big part of the equation here, and that's on a net well basis. And so just because of acceleration, instead of being like 50-50 in the first half, second half, we weighted it a bit more in the first half. And so that's really, so you, you know, so your question is right. Do you see it ramp up? And what you'll see is that the production will kind of be a little bit flatter, you know, obviously, has to be, you know, through the third quarter and then start ramping up a bit in the fourth.
spk12: Cash flow will be strong throughout there and, you know, we're carrying into 22 in good shape.
spk02: Okay. Well, that's helpful.
spk06: And maybe you could just kind of talk to the CapEx piece of it. You talked about kind of 60% of the completions in the first half, and it looks like you guys are on a run rate on first half CapEx, which looks like it's well below kind of your total 21 spend. So can you kind of maybe just help us a little bit here in the second half? Maybe there's some timing issues on some of the payments, but does CapEx kind of go up in the second half to hit the guide, or do you guys think you're kind of under budget, or what's happening with the capital dynamics?
spk12: We're firm on our 1.4. That would imply a little bit higher CapEx in the second quarter. It's just the timing. Bill or Jack referenced some incremental rigs earlier today. Some of those wells will be coming on early in 2022. I know you don't have guidance on 2022 yet, but we'll give you that as we go forward. It's just the timing of completions and when they come on and the application of those dollars. That's part of the reason I referenced earlier that we're set up well for 22.
spk11: Yeah, one way to maybe frame this is, you know, we set a dimension of a constraint on ourselves with $1.4 billion and looked to optimize the economics. And with that, said let's do what we can to get the most production on with the least amount of capital in the first half and then through the rest of the half, you know, go in with the rest of the spend on that. So that's why you see about $600 million spend, you know, in the first half and about 800 in the second half, but also why we brought all that production forward that Jack mentioned. So it's just a .
spk10: Yeah, and we also don't have any what you'd call ducts in the second half of the year as well. So you had some costs that were obviously expended in the prior year that ultimately turned into completed wells in the first half of the year. So we won't see any of that in the second half, really. We're keeping right up with Wells as they become available from a completion standpoint, which wasn't the case in late 2020.
spk06: Okay, that makes sense, guys. Thank you.
spk10: Thank you.
spk01: The next question comes from Oliver Huang of Tudor Pickering Holt & Co. Please go ahead.
spk00: Good morning, everyone. Hello. Good morning. Good morning. In the scoop, could you remind us what sort of spacing you all are running by targeted formation in the 21 program and if there have been any changes relative to the last two years or any thoughts on further widening out spacing there?
spk10: As far as spacing is concerned, it varies by formation and thickness of reservoir and all that. we don't really have, say, a quote set number of wells we drill per unit. It's area dependent and reservoir thickness dependent. But, you know, you can, you know, so I guess with that saying, we'll be anywhere, I would say, maybe 1,320 apart, maybe 880 feet apart, something like that in wells. But, again, it's area dependent. The interesting thing is that, you know, the Woodford wells that – we're showing here on slide 10 are actually pairs of wells, which is really interesting. The four of them are, well I guess really five of them are, that were drilled in 21 and they're basically 1,320 feet apart from themselves or the parent well. And the reason we did that was we wanted to get early indications of what unit development might look like. Interestingly enough, you look at the way the curves are, and it sure looks a lot like the 2020-21 Springboard 1 and 2 unit development curve. So again, consistency of performance. You know, these Sycamore wells on that chart are actually single, one-off parent wells. So we would expect to see them performing at a higher rate. And so all that said is that we are very cognizant of getting understanding of spacing, even in these other project, in these other areas, as soon as possible so we know how we can move into full unit development every time we drill a unit.
spk00: Okay, that's helpful, Culler. And for my second question, you all made significant advances on the DNC Prolateral Footfronts in both the Bakken and Oklahoma since 2018. Do you all see more running room on this front from improving completion techniques such as SimulFrac technology? And if so, could you expand on that opportunity set? Is this potentially a potential trough with how raw materials are trending higher? And also, if there's any color on how much inflation you all are baking in in the back half this year.
spk09: Thanks. And this is Pat Bent, and that's a lot of questions. So when I think about is there any additional running room, the answer to that is yes. We continue from an engineering perspective to build in natural improvements. that help us lower our costs from a technical design on the drilling side to a stimulation design on the completion side, we see an additional running room. Obviously, we feel good about being on track to reach our targets here in 21, and so that incorporates any modest pricing pressure inflation that we might see through the year, which we do and which we are offsetting. There is pressure from a steel perspective, but that doesn't amount to a significant component of our completed well cost. We've got good pricing in place through September and we'll have through the end of the year that keeps any impact from the steel side of the business to just around that 5% of a completed well cost. So feel real strongly about our ability to continue to manage costs through engineering and leveraged procurement, and so I see that continuing through the rest of this year.
spk11: Yeah, Oliver, one other thing I may build on that. One thing that we did all through 2020 is we didn't have layoff programs, and so although we slowed down on our activity, we had all that engineering talent in Pat's group continuing to focus on, hey, how do we optimize this? So we were able to come out of the gate running with lots of opportunities, but there's a lot of things that they studied during that last year we actually have not implemented yet. So to Pat's point, you know, we're still looking at, you know, a lot of things when it comes to time, how they do all these activities faster, time is cost. So that's one part of it. And the other one that Pat mentioned is looking at technologically, how do we do it differently? How do we improve on the way we've been doing in the past? And, you know, the 30% learning curve is pretty significant since 2018. That's quite typically a learning curve over a life. And we We feel that still got a lot of running room in front of us, as Pat was describing.
spk01: This concludes our question and answer session. I would like to turn the conference back over to Rory Sabino for any closing remarks.
spk08: Great. Thank you very much for joining us today. Please reach out to the IR team with any further questions. We appreciate your time. Thank you.
spk11: Thank you, everyone. Thank you.
spk01: The conference is now concluded. Thank you for attending today's presentation and you may now disconnect.
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